Method and Device to Remove Hydrogen Sulfide from Steam Condensate in a Geothermal Power Generating Unit

ABSTRACT

Ammonia sometimes present in geothermal steam increases the solubility of hydrogen sulfide in the steam condensate produced by the surface condenser in a steam cycle geothermal power generating unit by reacting with the hydrogen sulfide to produce nonvolatile ammonium bisulfide. The condenser vent gas also produced contains carbon dioxide. Contacting the steam condensate with the condenser vent gas at a pressure slightly greater than atmospheric causes carbon dioxide to dissolve in the condensate, decreasing pH and converting bisulfide ion back to hydrogen sulfide. Subsequently exposing the acidified condensate to condenser vacuum strips the hydrogen sulfide from the condensate, eliminating the need for further chemical treatment of the condensate to prevent air pollution. Hydrogen sulfide partitioning performance is further improved by converting the hydrogen sulfide in the vent gas to sulfur dioxide before contacting it with the condensate.

RELATED PATENT APPLICATIONS

Benefit is claimed of Provisional Patent Application 61/315,010 filedMar. 18, 2010.

FIELD OF THE INVENTION

A method and device are provided to remove hydrogen sulfide from thesteam condensate in a geothermal power generating unit, therebydecreasing the cost of air pollution control.

BACKGROUND OF THE INVENTION

The majority of steam turbine equipped geothermal power generating unitsare equipped with surface condensers. Because the volume ratio ofcondensate to vent gas is small, most of the noncondensible gases in thesteam—including hydrogen sulfide (H₂S)—leave the condenser with thecondenser vent gas. Well established processes (Stretford, LoCat,SulFerOx, combustion, regenerative thermal oxidation, etc., hereinafter“primary H₂S abatement”) are employed to remove essentially all of theH₂S from the vent gas before it is vented to the atmosphere, therebypreventing air pollution by toxic and extremely malodorous H₂S.

This simple and usually highly effective method of controlling airpollution becomes much less effective when the steam contains ammonia;notably, in the very large dry steam field in Sonoma County and LakeCounty, Calif. Ammonia—which is a base—reacts with H₂S—which is a weakacid—to produce a nonvolatile salt (ammonium bisulfide, NH₄SH) whichremains dissolved in the condensate:

H₂S+NH₃→HS⁻+NH₄ ⁺  (1)

As a result, a substantial fraction of the H₂S (as much as 35%) leavesthe condenser dissolved in the condensate instead of with the vent gas.Most of the steam condensate is provided to the cooling tower as make-upwater, and—if not further treated—most of the H₂S in the condensatewould be released from the cooling tower to the atmosphere, causing airpollution.

Several methods have been implemented to minimize release of H₂S fromthe cooling tower, but each has drawbacks.

1. The H₂S dissolved in the condensate can be destroyed using chemicaloxidation, commonly employing hydrogen peroxide, which is unstable,hazardous and expensive and requires expensive storage tanks and pumpsto keep it from decomposing, potentially in an explosive manner. Thismethod of so-called secondary H₂S abatement significantly increases thecost of power generated.2. A catalyst—iron complexed with EDTA, HEDTA or another chelatingagent—can be added to the cooling water to catalyze reaction of the H₂Swith oxygen dissolved in the cooling water before it is released to theatmosphere. Because a 2:1 or greater mole ratio of catalyst to H₂Sdissolved in the cooling water is required, the consumption and cost ofthe catalyst (which is lost with cooling tower blowdown and throughgradual decomposition) can be large when the amount of H₂S dissolved inthe condensate is large. Also, colloidal sulfur produced by theoxidation reaction and iron oxide from decomposition of the catalystproduce sediment and deposits that foul the condenser tubing, decreasingthermal efficiency of the power generating unit and necessitatingperiodic outages to clean the condenser and cooling tower.3. When the amount of H₂S in the condensate is small, microbes presentin the cooling water are able to consume most of the H₂S before it isemitted from the cooling tower. An appropriate population of microbesmust be maintained in the cooling water for this approach to work,requiring tight control of biocide usage. If too little biocide is addedto the cooling water, microbes proliferate and foul the condenser tubesand tower fill. If too much biocide is added, the population of microbesdecreases to the point that H₂S is emitted to the atmosphere. Also,microbial oxidation of H₂S produces colloidal sulfur. Even with tightcontrol, some amount of H₂S is emitted to the atmosphere, and depositsof biomass and sulfur in the condenser tubes require periodic cleaning.

Therefore, the geothermal industry has devoted much effort to decreasingthe amount of H₂S that dissolves in the condensate; indeed, surfacecondensers are commonly employed precisely because they put a largerfraction of the H₂S into the vent gas as compared to contact condensers,despite the fact that surface condensers are more expensive and lessefficient in terms of power generation than are contact condensers andrequire more maintenance.

In all cases, carbon dioxide is the major impurity present in geothermalsteam and is a major constituent of the condenser vent gas. A smallfraction of the CO₂ present in the steam dissolves in the condensateinside the condenser, and a small fraction of the CO₂ dissolved in thecondensate reacts with water to produce carbonic acid, which is a muchstronger acid than H₂S:

CO₂+H₂O→H₂CO₃K<0.002  (2)

The carbonic acid reacts with the ammonium bisulfide in the condensateconverting it back to H₂S which partitions into the vent gas:

H₂CO₃+HS⁻H₂S+HCO₃ ⁻  (3)

In principle, the presence of CO₂ dissolved in the condensate might beexpected to prevent H₂S from dissolving in the condensate. Because thesolubility of CO₂ in warm water is small and the partial pressure of CO₂inside the condenser is small, very little CO₂ actually dissolves in thecondensate. Furthermore, the reaction of CO₂ with water to producecarbonic acid is slow in relation to the limited time is available forthe reaction to take place before the condensate falls out from the twophase region inside the condenser and into the hotwell. For this reason,the CO₂ in the steam actually has little effect upon the solubility ofH₂S in the condensate, and fails significantly to decrease the cost andcomplications of secondary abatement.

PRIOR ART

Schwab et al. U.S. Pat. No. 1,851,987 teach removing dissolved sulfidesfrom waste water generated in connection with sulfur mining using theFrasch process by contacting the waste water with a gas stream thatcontains carbon dioxide. Smith U.S. Pat. No. 1,964,487 teaches a similarprocess, wherein the waste water is air stripped after being contactedwith combustion flue gas containing carbon dioxide.

Domahidy U.S. Pat. No. 4,402,713 teaches removing hydrogen sulfide fromsteam condensate in a geothermal power generating unit having two stagesof steam jet ejectors by using the entire volume of condenser vent gasmixed with steam flowing out of the first stage jet ejector to steamstrip the condensate in a stripping tower at essentially constantpressure approximately equal to the exhaust pressure of the first stagesteam jet ejector.

Domahidy U.S. Pat. No. 4,410,432 teaches compressing a fraction of thecondenser vent gas after it has been treated to remove H₂S andcontacting it in a countercurrent manner with a fraction of thecondensate extracted from the main condenser in an absorber column at apressure greater than ten atmospheres, whereby part of the CO₂ in thetreated condenser vent gas dissolves in the condensate, and a smallfraction of the dissolved CO₂ reacts to form carbonic acid. Thecondensate containing dissolved CO₂ and carbonic acid is then sprayedover the top of the tube bundles inside the main condenser. In thismanner carbonic acid is added to the condensate as it condenses in thetube bundles, decreasing pH and preventing H₂S from dissolving in thecondensate as ammonium bisulfide. Domahidy teaches (at 3:20-22) that“the major portion” of the condensate flowing out of the main condensergoes directly from the main condenser to the cooling water system. Thus,less than one-half of the condensate is contacted with condenser ventgas in the absorber column. In a practical implementation of Domihidy'sinvention much less than one-half of the condensate would go to theabsorber column in order to minimize pumping costs and avoid flooding ofthe heat exchange tubes when the acidified condensate is returned to thecondenser and sprayed over the tube bundles.

Borrel U.S. Pat. No. 5,911,853 teaches removing H₂S, mercaptans andother volatile sulfides from paper mill condensate by injecting CO₂ intothe condensate stream under pressure greater than atmospheric andpreferably in the range 30 to 100 psig, then rapidly reducing pressurethereby causing H₂S and other sulfides to pass from the CO₂-enrichedcondensate to a gas phase. Borrel teaches the second, reduced pressureas being equal to atmospheric or slightly above.

SUMMARY OF THE INVENTION

The invention disclosed herein is a method and device that can be calleda “condensate scrubber” which removes most of the H₂S from the steamcondensate in a geothermal power generating unit.

A simple installation of the condensate scrubber would require:

-   (a) A gas absorber that operates at a first pressure slightly    greater than atmospheric,-   (b) Means for conveying a fraction of the condenser vent gas to the    gas absorber,-   (c) A vapor/liquid separator connected to the main condenser and    maintained at a second pressure substantially equal to the pressure    in the main condenser, and-   (d) A second condensate pump to remove the treated condensate from    the vapor/liquid separator and deliver it to the cooling water    system (that is, in addition to the condensate pump that removes    steam condensate from the main condenser and is always present in a    steam cycle generating unit).

The first condensate pump removes condensate containing dissolved H₂Sfrom the hotwell of the condenser and brings it up to a first pressureslightly greater than atmospheric. This condensate is contacted with afraction of the condenser vent gas at this first pressure with a contacttime sufficiently long to allow CO₂ in the vent gas to dissolve in thecondensate and react with water to produce carbonic acid which thenreacts with bisulfide ion converting the bisulfide to H₂S. The gassaturated, mildly acidic condensate is then exposed to the second, lowerpressure, whereby a vapor phase separates from the condensate, and theH₂S and other gases dissolved in the condensate partition into the vaporphase which flows back to the main condenser. By this means most of theH₂S is removed from the condensate and returned to the main condenser,and is ultimately destroyed in the primary abatement system. Finally,the second condensate pump removes the condensate from the gas separatorand conducts it to the cooling tower.

The H₂S partitioning performance of the condensate scrubber can beimproved by employing two or more stages of gas absorption, by employingtwo or more stages of vapor separation, by increasing the temperature ofthe condensate to increase the volume ratio of vapor to liquid when itis depressurized, by steam scrubbing the condensate at the second, lowerpressure, or by adding SO₂ or another acid to the condensate to furtherdecrease condensate pH, thereby further decreasing the solubility of H₂Sin the condensate.

DESCRIPTION OF THE DRAWING FIGURES

FIG. 1 depicts the prior art in simplified form: a geothermal powergenerating unit equipped with a surface condenser and provision forprimary and secondary abatement of H₂S.

FIG. 2 is a simplified schematic of a power generating unit equippedwith a condensate scrubber.

FIG. 3 depicts in greater detail a power generating unit equipped withthe preferred embodiment of the condensate scrubber.

FIG. 4 depicts the preferred embodiment of the gas absorber subsystem ofthe condensate scrubber, comprising two steam jet ejectors to compressand transport the vent gas, and two tanks sparged with the vent gasallowing CO₂ to dissolve in the condensate.

FIG. 5 depicts an embodiment of the gas separator subsystem of thecondensate scrubber wherein acid can be added to decrease condensate pH.

FIG. 6 depicts a simpler embodiment of the gas separator subsystem whichis advantageously employed when an incinerator is used to convert H₂S inthe recirculated condenser vent gas to SO₂; that is, as part of thepreferred embodiment of the invention.

DESCRIPTION OF THE INVENTION

FIG. 1 depicts the prior art in simplified form: a geothermal powergenerating unit equipped with a surface condenser and provisions forprimary and secondary abatement of H₂S, but no condensate scrubber. Acomplete geothermal power plant would comprise one or more suchgenerating units.

In FIG. 1, solid arrows represent flows of liquid (that is, condensate).Dashed arrows represent flows vapor, steam or gas. Steam flows fromturbine 10 to main condenser 14 which comprises a large vacuum chamberwith one or more tube bundles inside of it. Condensate pump 28 removesthe condensate from the main condenser. Gas ejector system 18 removescondenser vent gas containing CO₂ and H₂S from the main condenser,brings it up to slightly above atmospheric pressure, and conducts it toprimary H₂S abatement system 26 which removes H₂₅ from the vent gasbefore releasing it to the atmosphere. The seal water flowing out of thevacuum pump contains the highest concentration of H₂S, and is delivereduntreated to injection well 39. The bulk of the condensate is deliveredto cooling tower 32 as make-up water. The chemical reactions thatcomprise secondary abatement process 30 take place as the condensateflows to the cooling tower.

Each arrow is labeled with a number enclosed in parentheses whichrepresents the percent of total H₂S entering the power generating unitthat is carried by that particular flow of steam, condensate or vapor.These mass flows of H₂S were calculated in reference to a geothermalpower generating unit of contemporary design, assuming the steamcomposition in Table 1.

FIG. 2 depicts the same geothermal power generating unit with thecondensate scrubber implemented in its simplest, essential form. Firstcondensate pump 28 removes the condensate from main condenser 14 anddelivers it to gas absorber 46. This pump is selected to providesufficient head to get the condensate out of the hot well of thecondenser and into gas absorber 46; the power consumed by this pump isone of the parasitic loads aggregated in Table 4. Small steam jetejector 42 diverts a fraction (typically about 20%) of the condenservent gas exiting gas ejector system 18 to gas absorber 46 where the ventgas contacts the condensate slightly above atmospheric pressure,allowing a substantial fraction of the CO₂ in the vent gas to dissolvein the condensate. Because the pressure in gas absorber 46 willtypically be at least ten times greater than the operating pressure inmain condenser 14, at least ten times more CO₂ will dissolve in thecondensate than dissolved when condensate first formed inside maincondenser 14. Gas absorber 46 provides sufficient residence time for thereaction of dissolved CO₂ with water producing carbonic acid (reaction 2above) to approach equilibrium, thereby decreasing the pH of thecondensate and converting practically all of the bisulfide ion in thecondensate to H₂S (reaction 3 above). The gases not absorbed (lesssoluble gases like N₂, CH₄, H₂ and a fraction of the CO₂) are conductedto primary H₂S abatement system 26 together with the rest of the gasstream from gas ejector system 18.

The acidified condensate then flows to gas separator 62 which isconnected to main condenser 14 whereby the pressure in gas separator 62is substantially equal to or just slightly greater than the pressure inmain condenser 14. Upon being exposed to the low pressure in gasseparator 62 the acidified condensate containing dissolved gasesseparates into two phases whereby most of the CO₂ and H₂S dissolved inthe condensate partition into the vapor phase. This vapor flows intomain condenser 14, and is subsequently removed from main condenser 14 bythe gas ejector system 18A, 18B, 18C and delivered to primary H₂Sabatement system 26. The liquid phase is removed from gas separator 62by second condensate pump 72 and delivered to cooling tower 32 where itserves as cooling water make-up. In this way most of the H₂S initiallydissolved in the condensate when it leaves main condenser 14 is strippedfrom the condensate and ultimately goes to primary H₂S abatement system26 where it is destroyed, and a much smaller amount of H₂S goes tosecondary abatement process 30 and cooling tower 32; indeed, secondaryabatement is optional and may no longer be needed.

Second condensate pump 72 is selected to provide the head necessary toget the condensate out of the main condenser and to the cooling tower;thus, this condensate pump consumes the same power as the singlecondensate pump of prior art, and does not represent a parasitic loadimposed by the condensate scrubber.

Small steam jet ejector 42 provides the essential pressure boost neededto convey part of the condenser vent gas to gas absorber 46, move thegas through gas absorber 46, and ultimately convey the remainder of thisvent gas not absorbed to primary H₂S abatement system 26. In principleanother kind of vacuum pump or compressor might be used for thispurpose, but a steam jet ejector is preferred because of small capitaland maintenance costs. Also, the steam that powers the gas ejectorincreases the enthalpy of the gas, whereby the enthalpy and temperatureof the condensate are increased, a greater volume of vapor is separatedfrom the condensate in gas separator 62, and H₂S is more thoroughlyremoved from the condensate.

Each arrow is labeled with a number that represents the percentage oftotal H₂S entering the power generating unit that is carried by thatflow. These values were calculated in reference to the embodiment of theinvention as depicted in FIGS. 3, 4 and 5 with operating values ofpressure and residence time as specified in Table 3, using the steamcomposition in Table 1, and no SO₂ or other acid added.

In the preferred embodiment of the invention incinerator 55 is providedwhich converts the H₂S in the vent gas that goes to the gas absorber toSO₂. In this embodiment H₂S is much more thoroughly removed from thecondensate without need for acid supplied from without the powergenerating unit.

FIG. 3 illustrates the invention in greater detail. In a typical modernsteam cycle geothermal power generating unit the gas ejector systemcomprises a single stage steam jet ejector 18A with intercondenser 18B,followed by vacuum pump 18C (prior art). Gas ejector 18A extractsnoncondensible gases 15 from main condenser 14 together with a smallamount of water vapor. Because the small stream of seal water 19 flowingout of vacuum pump 18C contains the highest concentration of H₂S in theentire power generating unit, it is advantageously diverted directly toinjection well 39 together with cooling tower blowdown 35 (prior art).

In the preferred embodiment of the invention, incinerator 55 convertsthe H₂S in noncondensible gas 40 to SO₂ which dissolves in condensate 53lowering the pH of the condensate whereby more H₂S is released fromsolution. Air 55A or oxygen must be provided to incinerator 55 in anamount sufficient to enable complete conversion of H₂S to SO₂. Any oneof a variety of incinerator types can serve this function; for example,a simple combustor (if the vent gas has sufficient fuel value), aregenerative thermal oxidation unit, a recuperative thermal oxidationunit, or a catalytic incinerator as provided by Haas, U.S. Pat. No.4,171,347.

In the preferred embodiment of the invention gas absorber 46 comprisesat least two stages 46B and 46A through which a portion of the condenservent gas 40 flows countercurrent to condensate 51. Countercurrent gasabsorption maximizes the amount of CO₂ absorbed from vent gas 40 therebyminimizing the volume of vent gas that must be passed through the gasabsorber. Each gas absorber stage 46B and 46A is provided with aseparate steam jet ejector 42A and 42B to move vent gas 40 through it.

Because the volume of vent gas 40 moved is small and the pressureincrease required at each stage is modest, the amount of motive steam44A and 44B that needs be provided to small steam jet ejectors 42A and42B is small, and the resulting increase in the temperature ofcondensate 47 leaving the gas absorber system is also small.Advantageously, additional steam 48 may be added to condensate 47 tofurther increase the temperature of the condensate, whereby a largerfraction of dissolved H₂S will be removed when condensate 47 is flasheddown to main condenser pressure in gas separator 62. While a relativelysmall amount of high pressure steam diverted from turbine steam supply12 is needed to power small steam jet ejectors 42A and 42B, steam atlower pressure extracted from turbine 10 between turbine stages can beused to increase the temperature of condensate 47. So doing decreasesthe power cost of diverting steam 48 to heat condensate 47 because thesteam diverted has already done some work.

Because steam 12 entering turbine 10 of a geothermal power generatingunit commonly is close to saturation, the first moisture appears justafter the first stage of the turbine, and more moisture condenses as thesteam flows through the turbine, significantly decreasing the energyconversion efficiency of the low pressure turbine stages. Advantageouslyand most conveniently steam is extracted from turbine 10 around itscircumference adjacent to the tips of the turbine blades. Becausecentrifugal force causes the moisture to be concentrated near the tipsof the blades, extracting a small amount of steam from the circumferenceof the turbine removes a much larger proportion of the moisture from theturbine together with the steam, and decreasing moisture contentincreases the energy conversion efficiency of the turbine stagesdownstream. As a result, extracting steam 48 from the turbine to heatcondensate 47 decreases power generated by an amount that is less thanproportional to the amount of steam extracted.

Optionally, mixer 76 may be used to add a small amount of sulfur dioxideor another acid 74—for example, sulfuric acid which is inexpensive andproduces relatively noncorrosive salts when neutralized—to condensate47, thereby further decreasing pH and increasing the amount of H₂S thatis removed from the condensate in gas separator 62.

Essentially, gas separator 62 is a flash chamber and stripper columnoperated at the same pressure as main condenser 14 and connected to maincondenser 14 with a conduit for vapor 72. Condensate 47 separates intotwo phase in gas separator 62, and vapor phase 72, which contains mostof the H₂S that was in condensate 47, flows into main condenser 14 whereit combines with steam 13 flowing out of turbine 10.

Advantageously, steam stripping column 63 can be provided to stripadditional H₂S 92 from the condensate. Advantageously and for reasonsrecited above, steam 84 provided to stripping column 63 is alsoextracted from turbine 10 between stages.

Optionally, second mixer 96 can be provided to add SO₂ or another acid98 to the condensate as it enters stripping column 63 whereby even moreH₂S is removed from condensate 94. Second condensate pump 100 bringscondensate 94 up to a pressure greater than atmospheric and conveys itto secondary H₂S abatement process 30 (which is now optional) andcooling tower 32.

FIG. 4 illustrates the preferred embodiment of the gas absorber portionof the condensate scrubber where steam condensate is contacted withcondenser vent gas. For reasons set forth above, it is advantageous toemploy two or more gas absorber stages 46B and 46A with condenser ventgas 40 flowing through them countercurrent to condensate 51.

Preferably, each gas absorber stage 46B, 46A is a tank filled withcondensate which is sparged with condenser vent gas 40, because a tankprovides time for the hydration reaction of CO₂ (reaction 2 above) toapproach equilibrium at each stage. The gas entering a tank typeabsorber near to its bottom must be compressed sufficiently to overcomehydrostatic pressure and to be dispersed as small bubbles in the liquid.Therefore, two steam jet ejectors 42A and 42B are advantageouslyprovided to propel vent gas 40 through absorber tanks 46A and 46B. Thegas entering each gas absorber 46A and 46B is dispersed into finebubbles through gas diffusers 41A and 41B. Condensate 51 enters secondgas absorber stage 46B propelled by first condensate pump 28 (in FIG. 3)at sufficient pressure to maintain liquid level 45B, and flows bygravity from second gas absorber stage 46B to first gas absorber stage46A wherein liquid level 45A is lower than liquid level 45B. Optionally,mist scrubbers 43A and 43B can be provided to remove liquid dropletscarried by the gases exiting gas absorber tanks 46A and 46B, wherebyerosion of second small steam jet ejector 42B and accumulation of liquidin pipes downstream are minimized.

FIG. 5 illustrates the design of the gas separator section of thecondensate scrubber that is most advantageous when acid 74 and acid 98are added to the condensate. Condensate 47 from first stage gas absorber46A enters gas separator 62 through spray head 61 having orifices 61Awhich distribute the condensate over first packed column section 64which is filled with Raschig rings or similar packing material. Orifices61A are sized such that most of the pressure drop between first stagegas absorber 46A and gas separator 62 takes place at orifices 61A,whereby separation of vapor from liquid commences as condensate 47passes through orifices 61A. First packed column section 64 improvesseparation of vapor from liquid, and should be sized to provide at leastone mass transfer unit. Mist catcher 66 removes water droplets fromvapor 72 flowing out of gas separator 62.

Mixer 74 preferably is an in-line mixer which ensures very rapid andthorough mixing of acid 74 with condensate 47. Bottom part 68 of gasseparator 62 preferably is cone shaped, allowing clean separation ofvapor from condensate 69 which collects in bottom part 68.

In-line mixer 74 and spray head 61 are designed to minimize the transittime of condensate 47 from the point acid 74 is added to condensate 47to where vapor begins to separate from it upon exiting orifices 61A. Theshortest possible transit time is desired because the reaction of acid74 with bisulfide ion in condensate 47 converting it to H₂S and thereaction of acid 74 with bicarbonate ion converting it to carbonic acidH₂CO₃ are limited only by the rate of mixing within in-line mixer 74 andtherefore practically instantaneous. The pH of condensate 47 when acid74 is added to it is buffered only by these reactions and decreasessignificantly. Subsequently, the carbonic acid thus formed decomposes torelease CO₂ and pH increases, but this reaction is much slower.Therefore, it is desirable to separate vapor from the condensate as soonas possible after complete mixing is achieved, before the pH of thecondensate has time to increase, converting part of the H₂S back tobisulfide ion.

Optionally, stripping column 63 can be added to the condensate scrubbersystem to remove additional H₂S from condensate 69 flowing out of bottompart 68 of gas separator 62. Additional acid 98 can be added tocondensate 69 and second in-line mixer 96 is provided to ensure thoroughmixing of acid 98 with condensate 69. Perforated tray 82 evenlydistributes the condensate over the top of second packed column section86 where the condensate meets steam 84 in a counter-flowing manner,whereby additional H₂S is stripped from the condensate. Second packedcolumn section 86 is filled with Raschig rings or similar packingmaterial, and preferably is designed provide at least one transfer unit.Perforated tray 82 is designed to allow flow of vapor up through theperforations while condensate flows down through the perforations; thiscounterflow is enabled by providing risers 82A with serrated upper edgeswhich tend to equalize liquid flow through each perforation, anddiameter large enough to allow vapor to flow up through them with aminimal pressure drop.

For reasons set forth above, in order to maximize the amount of H₂Sstripped from the condensate, in-line mixer 96 and perforated tray 82are designed to minimize transit time from the point that acid 98 isadded to condensate 69 to the point at which the falling condensateeffectively meets up-flowing steam at the top of second packed columnsection 86.

The steam stripped condensate accumulates in hot well 88 and is removed94 from steam stripper 63 by the action of second condensate pump 100.

In the preferred embodiment of the invention incinerator 55 produces SO₂and no additional acid 74 or 98 needs to be added to the condensate. Inthis case mixers 76 and 96 are not needed, and the gas separator systemdepicted in FIG. 5 can advantageously be replaced with the simplerdevice depicted in FIG. 6.

OPERATION OF THE INVENTION

Operation of the invention was modeled using the computer program CNDSR,which was specifically developed to model partitioning of H₂S and othergases in the condensers and cooling water system of a geothermal powergenerating unit (Weres, Geothermics, Vol. 12, pp. 1-15, 1983; Weres,Geothermics, Vol. 13, pp. 293-304, 1984; Weres, Geothermics, Vol. 13,pp. 305-318, 1984).

The steam composition assumed in modeling the invention is presented inTable 1, and Table 2 summarizes the fate of H₂S entering the powergenerating unit under several different scenarios. “Prior Art”represents a typical modern steam cycle geothermal power generating unitequipped with a surface condenser and a primary H₂S abatement system. Inthis case, which FIG. 1 is based on, 34.2 percent of the H₂S must bedestroyed by the secondary abatement process or else would be emitted tothe atmosphere.

“Invention” refers to basically the same power generating unit, butequipped with a condensate scrubber and wherein 20% of the condenservent gas is provided to the condensate scrubber. The “No Acid” case,which FIG. 2 is based on, represents operation of the invention withoutaddition of acid 74 or acid 98 to the condensate, and with no conversionof H₂S to SO₂. In this case, the amount of H₂S that must be destroyed bythe secondary abatement process is reduced to 2.5% whereby the cost andinconvenience of secondary abatement will small if, indeed, secondaryabatement is still needed to meet regulatory requirements.

The case labeled “H₂SO₄” assumes that sulfuric acid is added to thecondensate in an amount equal to 1.5 mg-moles per kg of turbine steamflow (147 ppm), equally divided between injection points 74 and 98. Inthis case, secondary abatement probably would be unnecessary, as only0.41% of the H₂S would be emitted to the atmosphere without it.

In the case labeled “SO₂” incinerator 55 converts the H₂S inrecirculated vent gas 40 to SO₂, and air 55A sufficient to provide a 40%stoichiometric excess of oxygen is supplied to the incinerator. In thiscase, only 0.23% of the H₂S coming into the power generating unit isemitted to the atmosphere, and secondary abatement certainly would notbe necessary. Because SO₂ is more soluble by several orders of magnitudethan H₂S at cooling water pH and would quickly be oxidized by reactionwith oxygen dissolved in the cooling water, the amount of SO₂ emitted tothe atmosphere is at least one hundred times smaller than the smallamount of H₂S emitted.

Table 3 summarizes the values of pressure and residence time of liquidin various parts of the power generating unit and condensate scrubber.These values are parameters that characterize the design of the powergenerating unit, and were specified in constructing the computer models.The values of temperature and pH were calculated.

In the “No Acid” case, condensate pH values in the main condenser andintercondenser are slightly lower than in the “Prior Art” case, whilecooling water pH is substantially higher, because more CO₂ and H₂S isremoved from the condensate before it is added to the cooling water. Thelowest pH in the entire system is 6.27 in first gas absorber tank 46A.

With sulfuric acid added, the lowest pH in the system is 5.94 in firstmixer 76. In the “SO₂” case, the pH in some parts of the system isactually greater than with “No Acid”; this increase is due to the factthat the air added to vent gas 40 to convert H₂S to SO₂ increases thevaport-to-liquid volume ratios in gas absorber tanks 46A and 46B,whereby less CO₂ is absorbed. Of course, oxidation of SO₂ to sulfuricacid in the cooling water decreases cooling water pH relative to the “NoAcid” case, but the pH of the cooling water coming from the coolingtower is still greater than in the “Prior Art” case.

Thus, the amount of sulfuric acid or SO₂ that needs be added to thecondensate to virtually eliminate H₂S emissions to the atmosphere willnot decrease pH values to the degree that corrosion will become asignificant problem.

The power needed to operate second condensate pump 100, and thepotential power generation lost by increasing steam supply to jetejector 18B, supplying steam 44A and 44B to power small jet ejectors 42Aand 42B, and extracting steam 48 and 84 from the turbine to heat andsteam strip the condensate will together represent the major operatingcosts of the invention. The power consumed, and potential powergeneration lost can be considered parasitic loads. The results of thiscalculation are summarized in Table 4. It was assumed that thebeneficial results of extracting a disproportionate amount of moisturefrom the turbine will decrease the power lost due to extracting steamfrom the turbine by 30%. In the “No Acid” case or with sulfuric acid,the effective parasitic load imposed is estimated to be 0.98%. Theparasitic load is about 0.90% when using incinerator 55 to produce SO₂because less CO₂ is recirculated to the main condenser in this case.

These parasitic loads can be decreased by optimizing operatingparameters. The largest parasitic load is the additional steam consumedby jet ejector 18B due to recirculation of part of the vent gas. As apractical matter, some power generating units operate with more steamsupplied to the jet ejector 18B than is necessary; in this case,increasing the load on the gas ejector system by a few percent would notrequire a commensurate increase in motive steam consumed.

CONCLUSIONS AND RAMIFICATIONS

This invention will allow the partitioning of H₂S in a steam cyclegeothermal power generating unit to be improved to the point thatsecondary H₂S abatement is no longer necessary.

Adding the condensate scrubber to a power generating unit in which anincinerator serves as part the primary H₂S abatement system would beespecially convenient. In this case, no additional incinerator 55 wouldbe needed, because part of the gas from the primary H₂₅ abatement systemcontaining SO₂ would be provided to the gas absorber.

By greatly reducing the amount of H₂S added to the cooling water andthereby reducing or completely eliminating the need to add chelated ironto the cooling water, the condensate scrubber will substantiallydecrease the accumulation of iron oxides, colloidal sulfur, and biomassin the cooling water system. This beneficial change will make it mucheasier to keep the condenser tubes and cooling tower fill clean. Theresulting increase in thermodynamic efficiency and decreased down timewill more than compensate for the modest parasitic load imposed by thecondensate scrubber.

While the embodiments described herein refer to a specific, typicalpower generating unit configuration, the invention can be implemented inpower generating units of different design. For example, the inventioncan be implemented in a power generating unit that employs an additionalsteam jet ejector in place of vacuum pump 18C or in a power generatingunit that does not dispose of any untreated condensate directly toinjection well 39.

Most beneficially, substantially all of the steam condensate which isused for cooling tower make-up should treated, and certainly at leastone-half of the steam condensate coming out of the main condenser shouldbe contacted with the condenser vent gas and treated.

While steam jet ejectors 42 (referring to FIG. 2) are considered thebest suited means for moving the condenser vent gas to and through gasabsorber 46, other gas propelling means could also be employed for thispurpose; for example, mechanical compressors or blowers. Because theamount of CO₂ that dissolves in the condensate increases with thepressure in gas absorber 46, it is preferred that the condenser vent gasbe pushed through the absorber at a pressure somewhat above atmospheric.However, the vent gas could also be pulled through the absorber, using asteam jet ejector or blower at the outlet of the absorber to pull it outof the absorber and push it towards primary H₂S abatement system 26after it leaves the gas absorber.

Using sparged tanks as illustrated in FIG. 4 to contact the steamcondensate with condenser vent gas is preferred, because tanks ofconveniently small size would provide the residence time needed for CO₂to react with water to produce carbonic acid and decrease pH before thecondensate is exposed to the second, lower pressure in gas separator 62.However, an absorber column or tower of conventional design could alsobe used for this purpose.

The gas absorber is most beneficially operated at a pressure aboveatmospheric but no more than twice the ambient atmospheric pressure.Increasing absorber pressure beyond that would bring diminishing returnswhile increasing the power required to pump the condensate into theabsorber and increasing the steam or power required to compress thecondenser vent gas.

Using untreated condenser vent gas (that is, condenser vent gas that hasnot yet passed through the primary H₂S abatement system) to acidify thecondensate is preferred, because using treated condenser vent gas (thatis, coming out of the primary H₂S abatement system with some amount ofair added to it) would increase the load on the primary H₂S abatementsystem in terms of gas volume being treated. However, treated vent gascould also be used, and certainly would be used in case the primary H₂Sabatement system is an incinerator that destroys the H₂S in the vent gasby converting it to SO₂.

In the example presented, 20% of the condenser vent gas is contactedwith the condensate. This percentage is subject to optimization, andactual percentage preselected will depend on the concentration of CO₂ inthe condenser vent gas, the amount of CO₂ that needs to be added to thecondensate to convert most of the bisulfide ion to H₂S, and the pressurein the gas absorber along with other factors. However, in most casesless than one-half of the condenser vent gas will suffice.

The simplest way to depressurize the acidified condensate to strip outthe H₂S is to expose it to condenser vacuum. This is most convenientlyaccomplished using a separator in the form of a separate vesselconnected to the vacuum chamber of the main condenser through a conduitlarge enough to allow the vapor separated from the condensate to flow tothe main condenser with a minimal drop in pressure. Ideally, thepressure in the gas separator should be substantially equal to theoperating pressure inside the main condenser, and in no event should thegas separator be operated at twice the main condenser pressure or above.

The gas separator can also be incorporated in the main condenser itself,by installing it inside the vacuum chamber of the main condenser. Inorder to avoid interference with steam flow from the turbine into theseparator, the gas separator should not be installed above any one ofthe tube bundles, and, of course, mixing of the treated condensate withuntreated condensate should be avoided.

TABLE 1 Steam Composition Modeled Parameter Units Total Gas Contentweight % 0.9 H₂S in steam mg/kg-H₂O 596 NH₃/H₂S mole ratio 1.05 H₂S insteam mmole/kg-H₂O 17.52 NH₃ same 18.33 CO₂ same 174.20 CH₄ + H₂ same68.66 Total Gas Content same 278.70

TABLE 2 Fate of Hydrogen Sulfide entering the Power Generating UnitInvention Prior Art No acid H₂SO₄ SO₂ Disposed to injection well 39 with9.6 10.1 9.6 9.1 vacuum pump seal water 19 Converted to SO₂ byincinerator 55 0.0 0.0 0.0 14.7 Destroyed in primary H₂S 56.2 87.4 90.076.0 abatement system 26 Destroyed by secondary H₂S 34.2 2.5 0.41 0.23abatement process 30 or emitted to the atmosphere

Tabulated values are percentages relative to total hydrogen sulfideentering the power plant.

TABLE 3 Values in Computer Models, Specified and Calculated InventionPrior Art t_(res) P T pH T Unit Label (s) (mbar) (° C.) No Acid H₂SO₄(a) SO₂ (b) (° C.) pH Main Condenser 14, 16 2 70 38.4 8.90 8.90 8.9338.6 9.04 Intercondenser 18B 2 183 48.5 8.42 8.41 8.47 49.1 8.55 GasAbsorber 1 46A 60 1100 41.9 6.27 6.26 6.33 Gas Absorber 2 46B 60 110040.3 6.56 6.54 6.75 Mixer 1 76 0.3 900 41.9 6.27 5.94 Gas Separator 621.0 73 38.6 7.73 7.46 7.29 Mixer 2 96 0.3 73 38.6 7.74 6.23 StrippingColumn 63 1.0 73 39.6 7.95 7.07 Cooling Water to Cooling Tower 32.1 7.907.51 7.26 31.9 7.27 Cooling Water from Cooling Tower 20.6 8.13 7.76 7.5120.6 7.29 Values of residence time and pressure specified; values oftemperature and pH calculated. Fraction of condenser vent gas providedto gas absorber section is 20%. (a) Sulfuric acid applied = 1.5mmoles/kg turbine steam flow, equally divided between Mixer 1 and Mixer2. (b) Hydrogen sulfide in gas recirculated to gas absorbers convertedto SO₂ in catalytic converter 53; 40% excess air provided.

TABLE 4 Steam and power required to operate the invention Amount inRelation to Effective Parasitic Turbine Steam Flow (%) Load (%) H₂SO₄(a) H₂SO₄ (a) or No Acid SO₂ (b) or No Acid SO₂ (b) Additional steam at4.7 bar to primary gas ejector 18A needed to remove 0.35 0.24 0.35 0.24recirculated gases from main condenser. Steam 44A and 44B at 4.7 bar topower small jet ejectors 42A and 42B 0.14 0.20 0.14 0.20 which moverecirculated gases 40 through gas absorbers 46A and 46B. Steam 48 at 1.4bar to increase temperature of the condensate; see note (c) 0.38 0.320.18 0.15 below. Steam 84 at 0.8 bar to steam strip condensate; see note(c) below. 0.55 0.55 0.20 0.20 Power to drive condensate pump 28 at 12.2m head and 23% energy 0.11 0.11 0.11 0.11 efficiency as percentage ofGross Power Generated. Total Effective Parasitic Load as Percentage ofGross Power Generated (%) 0.98 0.90 Notes (a) and (b) same as for Table3. (c) The effective parasitic load was estimated assuming that moisturerelated effects decrease loss of power caused by withdrawing steam fromthe turbine by 30%.

1. A method for removing hydrogen sulfide from steam condensate in ageothermal power generating unit which has a surface-type main condensercomprising a vacuum chamber and one or more tube bundles, and producessteam condensate flowing out of said main condenser and containingdissolved hydrogen sulfide and ammonia, and produces condenser vent gascomprising carbon dioxide, said method comprising contacting apredetermined portion of said steam condensate with a predeterminedportion of said condenser vent gas at a first pressure, and subsequentlyexposing said predetermined portion of said steam condensate to a secondpressure which is less than said first pressure at a location which isnot above any one of said tube bundles and inside of said vacuumchamber.
 2. The method of claim 1 wherein said predetermined portion ofsaid steam condensate is at least one-half of said steam condensateflowing out of said main condenser.
 3. The method of claim 1 whereinsaid main condenser is characterized by a value of operating pressure,and said second pressure is less than twice said operating pressure. 4.The method of claim 3, wherein said first pressure is not more thantwice the ambient atmospheric pressure.
 5. The method of claim 3,comprising the additional step of adding an acidic substance to saidsteam condensate before it is exposed to said second pressure.
 6. Themethod of claim 5, wherein said acidic substance is sulfur dioxide. 7.The method of claim 6, wherein said sulfur dioxide is derived fromhydrogen sulfide in said condenser vent gas.
 8. The method of claim 3,wherein said geothermal power generating unit has a steam turbine, andsteam extracted from said steam turbine is added to said predeterminedportion of said steam condensate after it has been contacted with saidcondenser vent gas.
 9. The method of claim 4, wherein said predeterminedportion of said steam condensate is substantially all of the said steamcondensate which is used as cooling tower make-up water.
 10. The methodof claim 9, wherein said second pressure is substantially equal to saidoperating pressure of said main condenser.
 11. In a geothermal powergenerating unit which has a surface-type main condenser comprising avacuum chamber and one or more tube bundles, and produces steamcondensate flowing out of said main condenser and containing dissolvedhydrogen sulfide and ammonia, and produces condenser vent gas comprisingcarbon dioxide, the improvement comprising, means for contacting apredetermined portion of said steam condensate with a predeterminedportion of said condenser vent gas at a first pressure, and means forsubsequently exposing said predetermined portion of said steamcondensate to a second pressure which is less than said first pressure.12. The geothermal power generating unit of claim 11, wherein saidexposing means are located outside of said vacuum chamber.
 13. Thegeothermal power generating unit of claim 11, wherein said exposingmeans are located inside of said vacuum chamber at a location not aboveany one of said tube bundles.
 14. The geothermal power generating unitof claim 11, wherein said predetermined portion of said steam condensateis at least one-half of said steam condensate.
 15. The geothermal powergenerating unit of claim 14, wherein said geothermal power generatingunit further comprises at least one condensate pump for bringing saidsteam condensate up to said first pressure before it enters saidcontacting means, and at least one additional condensate pump forpumping said steam condensate after it leaves said exposing means, andwherein said predetermined portion of said steam condensate issubstantially all of the said steam condensate which is used as coolingtower make-up water.
 16. The geothermal power generating unit of claim15, wherein said contacting means comprises one or more sparged tanks.17. The geothermal power generating unit of claim 16, further comprisinggas propelling means for moving said condenser vent gas through saidcontacting means.
 18. The geothermal power generating unit of claim 17,wherein said gas propelling means comprise steam jet ejectors.
 19. Thegeothermal power generating unit of claim 15, further comprising meansfor converting hydrogen sulfide in said condenser vent gas to sulfurdioxide.
 20. The geothermal power generating unit of claim 15, furthercomprising a steam turbine and means for extracting from said steamturbine a predetermined amount of steam which is subsequently combinedwith said steam condensate.